In many industries it is desirable to measure various parameters of fluids or fluid mixtures in pipes, including the temperature, pressure, composition (i.e., phase fraction, e.g., 10% water, 90% oil), flow rate, density, and/or the speed of sound (SOS) in the is fluid. (As used herein, “fluid” may refer to a liquid or gas, and a “fluid mixture” may be mixtures of liquids or gases or solids). Different sensor arrangements, referred to generically as “flow meters,” can be used to measure these parameters, such as those that are disclosed in the following U.S. patent applications, which are incorporated herein by reference in their entireties, and which may have issued as U.S. patents: Ser. No. 09/740,760, filed Nov. 29, 2000; Ser. No. 09/344,070, filed Jun. 25, 1999; Ser. No. 09/346,607, filed Jul. 2, 1999; Ser. No. 09/344,093, filed Jun. 25, 1999; Ser. No. 09/345,827, filed Jul. 2, 1999; Ser. No. 09/519,785, filed Mar. 7 2000; Ser. No. 09/346,606, filed Jul. 2, 1999; Ser. No. 09/346,604, filed Jul. 2, 1999; Ser. No. 09/346,605, filed Jul. 2, 1999; Ser. No. 09/344,094, filed Jun. 25, 1999; Ser. No. 10/010,183, filed Nov. 7, 2001; Ser. No. 09/344,069, filed Jun. 25, 1999; and Ser. No. 10/186,382, filed Jun. 28, 2002.
A flow meter typically comprises a sensor, a sensor array, or multiple sensor arrays. In many of these flow meters, the sensors may comprise fiber optic sensors, possibly incorporating fiber Bragg gratings (FBGs), which can be mounted or coiled around the pipe containing the fluid to be measured. Other flow meters allow optical devices or other sensing devices to be ported or placed within the pipe to make the required measurements. When one uses a fiber optic based flow meter, the fluid or fluid mixture parameters may be measured without the need to “tap in” to the pipe, as many of these parameters may be sensed externally to the pipe though the means disclosed in the above incorporated references. Often, these externally mounted sensors are “passive” sensors in the sense that they do not require stimulating the fluid or fluid mixture of interest by external means, but instead make the required measurements simply by sensing various naturally occurring fluid perturbations.
In the oil and gas industry, or comparable industries, it is desirable to measure, in situ, the flow produced from an oil well. Typically the produced fluid mixture may be comprised of three components or phases, such as oil, water, and gas, which may additionally contain other components, such as solids (e.g., rocks or sand) or other liquid phases. In a production environment, it is often useful to determine the phase fraction, or composition, of the fluid mixture being measured, as well as the speed of the flowing fluid or fluid mixture.
Techniques for measuring a fluid or fluid mixture flow rate exist in the prior art. For example, in U.S. patent application Ser. No. 09/346,607, entitled “Flow Rate Measurement Using Unsteady Pressures,” filed Jul. 2, 1999, incorporated herein by reference in its entirety, there is disclosed a flow rate meter which preferably utilizes fiber optic sensors. At least two fiber optic sensors are disposed at two different axial locations along a pipe containing the fluid to be measured. The first and second sensors are spaced at a predetermined axial distance apart. Naturally occurring pressure disturbances in the fluid, such as acoustic pressure waves and vortical pressure waves, perturb the first sensor through the wall of the pipe, creating a first time-based pressure signal. When the pressure disturbance, or pressure field, moves from the first sensor to the second sensor, a second time-based pressure signal is measured. The first and second signals can then be cross-correlated using well-known techniques to determine the time delay between the pressure signals. Dividing the known axial distance by this time delay provides the velocity of the fluid flowing through the pipe. The velocity may then be converted to volumetric flow rate by multiplying the velocity by the cross-sectional area of the pipe. Optionally, the sensors may comprise filters capable of filtering out pressure disturbances caused by acoustic pressure waves and other long wavelength pressure disturbances. This filtering results in a pressure signal largely indicative of vortical pressure disturbances occurring naturally in the fluid, thereby reflecting a more accurate depiction of the fluid velocity and flow rate.
Other flow rate techniques using venturis are also known in the art. For example, U.S. Pat. No. 5,591,922, entitled “Method and Apparatus for Measuring Multiphase Flow,” issued Jan. 7, 1997, and which is incorporated by reference herein in its entirety, describes a meter having a pair of venturis within a pipe spaced from one another at an axial distance. As is well known, the venturi causes a pressure difference (ΔP) at each venturi, which are measured. These differential pressure signals are cross-correlated to determine a time delay. Dividing the axial distance between the venturis by the time delay results in the flow velocity. Furthermore, given the volume between the two differential pressure measurements, the time delay makes it possible to determine the total volume flow rate by dividing the volume by the time delay.
Flow meters for determining phase fraction (“phase fraction meter”) in a fluid mixture are also known in the art. For example in U.S. Pat. No. 6,354,147, entitled “Fluid Parameter Measurement in Pipes Using Acoustic Pressures,” issued Mar. 12, 2002, which is incorporated by reference herein in its entirety, a spatial array of pressure sensors, preferably fiber optic sensors, are coupled to the outside of the pipe. Each sensor measures acoustic pressure disturbances and then provides acoustic pressure signals that are then used to determine the speed of sound of the mixture. Because the speed of sound of a given mixture is related to the fluid composition, the measured speed of sound can be used to directly determine the phase fraction of at least two-phase mixture, although it may be necessary or helpful to combine the measured sound speed with other known quantities to determine the phase fraction of a fluid containing more than two phases.
Often these various types of flow meters will be used in conjunction with each other to measure various fluid parameters of the device. For example, a flow rate meter may be used on one section of the pipe, followed downstream by a phase fraction meter, or vice versa. Or, these flow meters may be combined into an integrated flow meter apparatus, as described in patent application Ser. No. 09/740,760, entitled “Apparatus for Sensing Fluid in a Pipe,” filed Nov. 29, 2000, incorporated herein by reference in its entirety.
While these prior art techniques generally perform well, they may not be optimized for measuring the parameters of fluid mixtures having more than two phases, such as occurs following “gas breakthrough” during oil production. During early production, reservoir pressure is often sufficient for the produced hydrocarbons to remain under-saturated with gas as the fluids enter the production tubing. In this condition, a flow meter located at or near the sand face would encounter liquids only because the gases remain dissolved in the liquids. As the fluids move higher up the production string, the pressure decreases to below the “bubble point” of the fluids, allowing free gas to break out of the produced fluids. As the reservoir pressure is depleted, the point at which gas comes out of solution moves down the production tubing and often eventually into the reservoir itself. Consequently, any production flow meter would encounter free gas. The presence of gas can degrade the ability of a meter to measure fluid parameters, even if the meter was performing adequately up to the point of gas breakthrough.
The art would therefore benefit from ways to improve the performance of these and other traditional flow meters, especially with regard to their ability to measure more than two phases. Additionally, it would be desirable that the flow meter can adapt to changing conditions within the pipe, for example, as the breakthrough point moves down the well as a result of reservoir depletion.